American Electric Power Company, Inc. — 2011 Form 10-K
Reporting period: Fiscal year ended December 31, 2011; filed February 28, 2012. This combined filing covers AEP and five utility subsidiaries. It describes an integrated electric utility serving customers across 11 states, with approximately 37,000 MW of domestic generation capacity. The full consolidated financial statements and management discussion are incorporated by reference to the 2011 annual reports and are not included in the supplied filing text.
Financial results and position
- Revenue: The filing’s 2011 AEP System revenue table reports $15.116 billion total revenue, including $14.091 billion of utility operating revenue. Utility operating revenue comprised $11.617 billion retail sales, $2.254 billion wholesale revenue, and other electric and operating revenue. The table includes other subsidiaries and eliminates intercompany transactions; comparable prior-year system revenue is not provided in the supplied text.
- Parent-company earnings: AEP parent reported net income of $1.941 billion in 2011, versus $1.211 billion in 2010 and $1.357 billion in 2009. Basic and diluted EPS were both $4.02 in 2011, versus $2.53 in 2010. Parent earnings principally reflect equity earnings from subsidiaries ($1.980 billion in 2011), not stand-alone operating performance.
- Parent cash flow: Operating cash flow was $1.062 billion in 2011, compared with $772 million in 2010. Investing activities used $385 million and financing activities used $781 million; cash declined $104 million to $127 million at year-end.
- Parent debt and liquidity: At December 31, 2011, parent short-term commercial paper was $967 million (weighted-average rate 0.51%), compared with $650 million in 2010. Long-term debt was $554 million, versus $552 million. Parent cash was $127 million, and advances to affiliates were $944 million. AEP stated it was in compliance with debt covenants. These are parent-only figures, not consolidated AEP debt or liquidity.
- Margins and consolidated metrics: Consolidated net income, operating cash flow, margins, consolidated debt and consolidated liquidity are not clearly stated in the supplied text. The filing directs readers to the incorporated annual reports for those figures.
Changes and operating developments
- Parent net income increased about 60% and EPS rose from $2.53 to $4.02 year over year; the supplied text does not explain the consolidated drivers of this change.
- AEP System coal and lignite accounted for 78% of fuel used in 2011, down from 82% in 2010; natural gas rose to 11% from 8%, and nuclear to 10% from 9%. Natural gas consumption increased 25% year over year, while purchased coal’s average delivered price rose to $46.76 per ton from $44.82.
- Columbus Southern Power merged into Ohio Power on December 31, 2011; prior-period amounts for OPCo were recast as though the merger occurred at the start of the earliest period reported.
- Environmental investments were $186.8 million in 2011, down from $303.8 million in 2010. Forecast environmental spending rises to $510.7 million in 2012, $999 million in 2013 and $1.1 billion in 2014. Total 2011 construction expenditures were $2.669 billion; 2012 construction spending was forecast at approximately $3.065 billion.
Outlook, risks and unusual items
- Ohio regulation: In February 2012, after year-end, the PUCO rejected the approved modified electric security plan on rehearing and ordered a return to 2011 ESP rates pending a new plan. The order also disrupted the proposed generation corporate-separation plan and affected recovery mechanisms. AEP said it was evaluating its options; recovery of costs and future Ohio earnings remain uncertain.
- Generation and power-pool changes: AEP Power Pool members gave notice to terminate their Interconnection Agreement effective January 1, 2014, subject to FERC acceptance and state input. Replacement agreements, asset transfers and the resulting effects on power costs and sales had not been resolved.
- Environmental compliance: AEP expects substantial additional investment to meet air- and water-quality rules. New or changing requirements—including the Utility MACT rule, regional haze requirements, greenhouse-gas regulation and coal-ash rules—could raise operating and capital costs. Recovery through rates or market prices is not assured in amount or timing.
- Cook Nuclear Plant: Cook Unit 1’s 2008 turbine failure led to approximately $400 million in repair and replacement costs. The unit resumed operation in 2009 and a full-capacity turbine was installed in 2011; recovery through warranty, insurance and regulation remains a risk. The Cook decommissioning trust held approximately $1.3 billion at year-end 2011, against estimated 2009 nondiscounted decommissioning and low-level waste costs of $831 million to $1.5 billion.
- Other exposures: Disclosed risks include fuel and power-price volatility, weather and outages, rate-recovery lag, capital-market access and credit ratings, counterparty and trading risk, pension funding, and environmental and other litigation. AEP also identified potential refunds in Oklahoma fuel-cost proceedings and $108 million of unsettled gross SECA transmission revenues, against which it had recorded a provision.
- Projects and emissions: The 600 MW Turk coal plant was expected to enter service in late 2012; the 580 MW Dresden gas unit entered service in January 2012. AEP reported 2011 CO2 emissions of approximately 141 million metric tons, roughly flat with 2010. Its 2012 demand-reduction goal was 1,000 MW, subject to regulatory approvals and cost recovery.
- Controls and audit: Management reported effective disclosure controls and internal control over financial reporting, with no material weaknesses. Deloitte issued unqualified opinions on the financial statements referenced in the filing.
Key facts for investors to verify
- Review the incorporated consolidated financial statements and MD&A for AEP-wide revenue, earnings, cash flow, margins, debt, liquidity and year-over-year drivers; the parent-only figures above are not substitutes.
- Track Ohio PUCO decisions, the replacement ESP, cost-recovery outcomes and any revised corporate-separation or generation-transfer filings.
- Assess the scale, timing and recoverability of planned environmental and construction spending.
- Monitor FERC and state actions on termination of the AEP Power Pool agreement and the impact on generating-company costs and revenues.
- Verify resolution and financial recovery of the Cook Unit 1 costs, Oklahoma fuel-cost proceedings and remaining SECA refund exposure.